This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Many gas streams, for example natural gas, contain large amounts of acid gases that must be separated from the more valuable components in the gas. Natural gas from well production is used extensively as fuel and as a basic raw material in the petrochemical and other chemical process industries. While the composition of natural gas can vary widely from field to field, many natural gas reservoirs contain relatively low percentages of hydrocarbons (less than 40%, for example) and high percentages of acid gases, principally carbon dioxide, but also hydrogen sulfide, carbonyl sulfide, carbon disulfide, and various mercaptans. Sour gas is a mixture containing hydrogen sulfide, carbon dioxide, and hydrocarbons. Removal of the acid gases from sour gas is desirable to provide conditioned or “sweet” dry natural gas for delivery to a pipeline, natural gas liquids recovery, helium recovery, conversion to liquid natural gas, or nitrogen rejection.
The separated acid gases are available for processing, sequestration, disposal, or for further use. The acid gases have, for example, been reinjected into a subterranean formation for disposal and into hydrocarbon-bearing formations for hydrocarbon recovery. Acid gas injection (AGI) and sour gas injection (SGI) have been practiced for more than 15 years in onshore applications. Compression and pumping technology may include flows ranging from less than 1 Mscf/d to more than 80 Mscf/d. Pressures range up to 3,200 psi at the surface. The machinery utilized in AGI can be reciprocating compressors, centrifugal compressors and dense phase centrifugal or reciprocating pumps. Pumps are sometimes also combined with compressors to achieve higher injection pressures.
Reciprocating and centrifugal compressors have also been used to compress gas containing hydrogen sulfide for sales or injection, both onshore and offshore. Some reciprocating sales gas compressors have been used commercially to compress gas containing up to 1% hydrogen sulfide. In some cases, centrifugal compressors have been used commercially to inject gas containing approximately 5% hydrogen sulfide. Both of these examples utilize gas derived directly from production without an H2S removal process.
Additional information relating to the field of the invention can be found in: P. S. Northrop et al., “Cryogenic Sour Gas Process Attractive for Acid Gas Injection Applications,” Proceedings Annual Convention—Gas Processors Association, 14 Mar. 2004, pp. 1-8; International Patent Application No. WO 2006/132541; and U.S. Pat. No. 6,632,266.
Compression of acid and sour gases in an offshore environment has the potential to make new offshore fields viable. However, offshore platforms place unique constraints on the flexibility of operating in any compromised environment. There are limited opportunities for refuge or escape should the atmosphere contain harmful or flammable gases that have been released from the compressor or compression system. This is particularly true in the case of reciprocating compressors which exhibit sudden massive releases of sour gas in certain failure modes. There is a present need to decrease the health and regulatory risks and environmental damage due to unexpected release of acid gases from offshore acid gas compression. There is also a need for processes and systems that optimize the placement of a subsea compressor to further reduce the health and regulatory risks and environmental damage due to unexpected release of acid gases from subsea acid gas compression.